Method of improving conformance in steam floods with carboxylate steam foaming agents

ABSTRACT

The disclosed invention is a group of steam foaming agents for injection with steam and a non-condensable gas to decrease permeability in steam swept zones and increase oil recovery. The foaming agents have the general formula: 
     
         RO(R&#39;O).sub.n R&#34;CO.sub.2 M 
    
     where R is an alkyl radical, branched or linear, having from about 8 to about 24 carbon atoms in the alkyl chain, R&#39; is ethylene, propylene or a mixture of ethylene and propylene, n has an average value of about 3 to about 11, R&#34; is methylene or ethylene, and M is an alkali metal or ammonium ion.

BACKGROUND OF THE INVENTION

The present invention relates to carboxylate steam foaming agents whichwhen injected with steam and a non-condensable gas will significantlyimprove vertical conformance.

When an oil reservoir is subjected to steam injection, steam tends tomove up in the formation, whereas condensate and oil tends to move downdue to the density difference between the fluids. Gradually, a steamoverride condition develops, in which the injected steam sweeps theupper portion of the formation but leaves the lower portion untouched.Injected steam will tend to follow the path of least resistance from theinjection well to a production well. Reservoir permeability to steamalso increases as oil is swept out by the steam. Thus, areas of highpermeability will receive more and more of the injected steam whichfurther raises the permeability of such areas. This phenomenon exists toan even larger degree with low injections rates and thick formations.The steam override problem worsens at greater radial distances from theinjection well because steam flux decreases with increasing steam zoneradius.

Although residual oil saturation in the steam swept region can be as lowas 10%, the average residual oil saturation in the formation remainsmuch higher due to poor vertical conformance. It is because of thecreation of steam override zones that vertical conformance in steamfloods is usually poor.

It has long been the concern of the oil industry to improve the verticalconformance of a steam flood by reducing the permeability of the steamswept zone by various means. The injection of numerous chemicals such asfoams, foaming solutions, gelling solutions or plugging or precipitatingsolutions have been tried. Because of the danger of damaging thereservoir, it is considered important to have a non-permanent means oflowering permeability in the steam override zones. For this reason,certain plugging agents are deemed not acceptable. In order tosuccessfully divert steam and improve vertical conformance, the injectedchemical should be (1) stable at high steam temperatures of about 300°to about 600° F., (2) effective in reducing permeability in steam sweptzones, (3) non-damaging to the oil reservoir and (4) economical.

The literature is replete with references to various foaming agentswhich are employed to lower permeability in steam swept zones. Thefoaming agents of the prior art require the injection of anon-condensable gas to generate the foam in conjunction with theinjection of steam and the foaming agent. U.S. Pat. Nos. 3,366,175 and3,376,924 disclose the injection of a steam foam in a hydrocarbonreservoir at the interface between the hydrocarbons and the gas cap toaid in recovery. U.S. Pat. Nos. 3,410,344 and 3,994,345 disclose the useof a steam foaming agent selected from the generic groups ofpolyethoxyalkanols and alkylaryl sulfonates to reduce permeability insteam channels. The use of similar surfactants such as sodium laurylsulfoacetate and alkyl polyethylene oxide sulfate are disclosed asfoaming agents in carbon dioxide foams in U.S. Pat. Nos. 4,088,190 and4,113,011, respectively. U.S. Pat. No. 4,018,278 discloses the use ofsulfonated, ethoxylated alcohols or alkylphenols in surfactant floodingsolutions without the use of steam. A group of ether sulfonate foamingagents are disclosed in U.S. Pat. Nos. 4,540,049 and 4,540,050.

Several trademarked foaming agents have been field tested by petroleumcompanies in steam floods. These include such trademarked chemicals asStepanflo 30 sold by Stepan Chemical Co., Suntech IV sold by Sun Oil,Thermophoam BWD sold by Farbest Co. and COR-180 sold by Chemical OilRecovery Co. U.S. Pat. No. 4,086,964 discloses the use of ligninsulfonates for a foaming agent and U.S. Pat. No. 4,393,937 discloses theuse of alpha olefin sulfonates as a steam foaming agent. See also UnitedKingdom Pat. No. 2,095,309 for a disclosure of alpha olefin sulfonatefoaming agents.

Disclosures of laboratory and field tests of Stepanflo are contained inSPE Paper No. 10774 entitled "The Laboratory Development and FieldTesting of Steam/Noncondensible Gas Foams for Mobility Control in HeavyOil Recovery" by Richard E. Dilgren et al. presented at the 1982California Regional Meeting of the SPE held in San Francisco March25-26, 1982 and the Journal of Petroleum Technology, July 1982, page1535 et seq. The same Journal of Petroleum Technology also discussedtests conducted on Thermophoam BWD. Additional information on tests ofThermophoam BWD are also disclosed in Department of Energy PublicationsDOE/SF-10761-1, -2 and -3.

Tests of the COR-180 foaming agent of Chemical Oil Recovery Co. aredisclosed in SPE Paper No. 11806 entitled "Improvement in SweepEfficiencies in Thermal Oil-Recovery Projects Through The Application ofIn-Situ Foams" by R. L. Eson, presented at the International Symposiumon Oil Field and Geothermal Chemistry in Denver, June 1-3, 1983 andDepartment of Energy Reports Nos. DOE/SF/10762-1, -2 and -3.

SUMMARY OF THE INVENTION

The present invention pertains to novel steam foaming agents forinjection with steam and a non-condensable gas to decrease permeabilityin steam swept zones and ultimately, increase oil recovery with steamflooding. The novel foaming agents have the general formula

    RO(R'O).sub.n R"CO.sub.2.sup.- M.sup.+

where R is an alkyl radical, branched or linear, having from about 8 toabout 24 carbon atoms in the alkyl chain, R' is ethylene, propylene or amixture of ethylene and propylene, n has an average value of about 3 toabout 11, R" is methylene or ethylene, and M is an alkali metal orammonium ion.

DETAILED DESCRIPTION

The steam foaming agents for the present invention are highly effectivein reducing permeability of steam swept zones. These novel foamingagents have an affinity for formation areas of high permeability and lowoil saturation. When set up in such areas, they substantially reduce thepermeability of the steam swept zones, forcing steam into other, unsweptareas of the formation.

The novel steam foaming agents of the present invention are representedby the general chemical formula:

    RO(R'O).sub.n R"CO.sub.2.sup.- M.sup.+,

where R is an alkyl radical, branched or linear, having from about 8 toabout 24 carbon atoms, preferably about 11 to about 15 carbon atoms inthe alkyl chain, R' is ethylene, propylene or a mixture of ethylene andpropylene, preferably ethylene, n has an average value of about 3 toabout 11, preferably about 5 to about 9, R" is methylene or ethylene,and M is an alkali metal or ammonium cation. The preferred alkali metalions are sodium, lithium and potassium. It should be noted that n is anaverage value and that the invention compounds will normally havevarying degrees of ethoxylation or propoxylation.

These novel foaming agents are sufficiently stable at the hightemperatures encountered in steam floods (300° to 600° F.). They are notpermanent and do not damage the reservoir.

The most preferred foaming agent is the carboxylate

    CH.sub.3 (CH.sub.2).sub.10-14 O(CH.sub.2 CH.sub.2 O).sub.7 CH.sub.2 CO.sub.2 Na.

The mixture of steam, non-condensable gas and foaming agent can bringabout a substantial reduction in permeability when injected into thehigh permeability areas of the formation at almost any time. Verticalconformance will be significantly improved whether the steam foamingagent and gas is injected into the formation at the very beginning ofsteam injection, before steam breakthrough at the production well orafter steam breakthrough. The most preferred injection times occurshortly after steam injection has begun and a short time before steambreakthrough will occur at the production wells. In the first instance,the injection of the steam foaming agent and gas near the beginning ofsteam injection will help prevent narrow steam channels from beingformed and extended through to the production wells. The injection ofthe foaming agent prior to steam breakthrough will postpone the time ofsteam breakthrough and spread the steam over a wider area near theproduction wells.

The invention foaming agents will also work quite well if steambreakthrough occurred in the past and low oil saturation steam overridezones exist. But in such a situation, the foaming agent must be injectedin greater quantities to reduce permeability in a swept out area.Generally, the mixture of steam, gas and foaming agent must be injectedinto the reservoir at a higher pressure than the previous injection ofsteam so that the foam will move a sufficient distance into the highpermeability areas. However, the injection pressure must be less thanthe reservoir fracturing pressure or damage to the formation will occur.

The foaming agent and gas may be injected into the formation without theconcurrent injection of steam, provided that steam is injected into theformation prior to and after the injection of the foaming agent and gas.But preferably, the steam is coinjected with the foaming agent and gas.

The foaming agent, non-condensable gas and steam should be injected in amixture such that the foaming agent comprises about 0.01% to about 5%preferably about 0.02% to about 1.5% by weight of the steam (cold waterequivalent). The foaming mixture contains about 0.01 to about 5,preferably about 0.01 to about 1.5 thousand standard cubic feet of anon-condensable gas per barrel of steam (cold water equivalent). It iscontemplated that the injected steam range from about 20% to about 90%quality. Individual tests should be run to tailor the concentration ofthe foaming agent in steam as the increased effectiveness of the foamingagent per increased concentration of foaming agent quickly reaches apoint of diminishing returns. Furthermore, other surfactants may also beincluded in the steam and foaming agent mixture to increase oil recoveryproviding they do not substantially inhibit the foam.

In general, the non-condensable gas used in the foam mixture of thepresent invention can comprise substantially any gas which (a) undergoeslittle or no condensation at the temperatures and pressures at which thefoam mixture is subjected, and (b) is substantially inert to andcompatible with the foaming agent and other components of that mixture.Such a gas is preferably nitrogen but can comprise other substantiallyinert gases, such as air, ethane, methane, flue gas, fuel gas, or thelike.

Two conditions will be prevalent in a steam override zone, especially ina well developed override zone. The steam flux in the override zone willbe high relative to other portions of the reservoir because the vastmajority of the steam will be passing through the override zone. Inaddition, the residual oil saturation in the override zone will berelatively low due to continuous steam flooding.

No chemical or physical deterioration has been detected in the foamingagents used in the formation at steam injection temperatures.Additionally, no problems have been encountered with thermal orhydrolytic stability of the agents. The foams tested have continued tobe effective up to three days but since the foaming agent will beeventually produced, it is generally necessary to continue injectingfoam into the high permeability areas. Cooling problems also fail toaffect foam stability. This is because the foam will go preferentiallyinto the high permeability areas of the steam override which are veryhot. The cool areas of the formation are those areas of low permeabilitywhich the foam will avoid.

Additional discussion and experimental correlations on steam foamingagents can be found in U.S. Pat. Nos. 4,540,049 and 4,540,050, thedisclosures of which are incorporated herein by reference.

The following examples will further illustrate the novel steam foamingagents of the present invention. These examples are given by way ofillustration and not as limitations on the scope of the invention. Thus,it should be understood that the composition and concentration of thefoaming agents may be varied to achieve similar results within the scopeof the invention.

EXAMPLES 1-12

Multiple runs were made in a foam testing apparatus to determine theeffectiveness of the foaming agents of the present invention and severalwell known steam foaming agents when injected with steam in the absenceof a non-condensable gas. A 90 cm linear cell with an inside diameter of3.4 cm was packed with sand, oil and water to a porosity of 0.4 and anoil saturation of 0.23. The sand pack was steam flooded at a backpressure of 200 psig and an injection rate of 4 ml per minute of steam(cold water equivalent) until no more oil was produced. This left aresidual oil saturation of 10.2%. The pressure drop across the celllength with the steam injection only was measured and determined to beapproximately 15 psig.

A high concentration of 6% active foaming agent (corresponding to abouta 1% in situ concentration in the aqueous phase in the cell) was theninjected with steam at approximately 0.5 ml per minute. Steam injectionwas held constant at 4.0 ml/min. The pressure drop was recordedcontinuously. When the pressure drop stabilized, nitrogen was injectedat 8.4 ml/min. Once the pressure drop restabilized, it was recorded foreach foaming agent.

The foaming agents tested in Examples 1-7 are identified below. Agent 1is a carboxylate employed in the present invention and Agents 2-7 areether sulfonates disclosed in U.S. Pat. No. 4,540,050. Examples 8-12were run to test and compare commercially available steam foamingagents. Table 1 illustrates that the carboxylate Agent 1 performedalmost as well as the ether sulfonate Agents 2-5 and significantlybetter than the commercially available steam foaming agents. ##STR1##

                  TABLE I    ______________________________________               Pressure Drop Across Cell               (psi) at N.sub.2 Flow Rates Of         Foaming     0 ml/    8.4 ml/                                     16.8 ml/                                            25.2 ml/    Ex.  Agent       min      min    min    min    ______________________________________         Steam Only  10     1   Agent 1              194     2   Agent 2     120      312    355     3   Agent 3     185      250    360     4   Agent 4     10       260    280     5   Agent 5              295     6   Agent 6              129     7   Agent 7     10        15     16    126     8   Stepanflo   10        25     25     40         30     9   Stepanflo   10       134    178         1390    10   Thermophoam 10        64     69    144         BWD    11   Bioterge    10       130         AS-40    12   Suntech IV  10       141    139    143    ______________________________________     Stepanflo 30 and 1390  trademarked alpha olefin sulfonates sold by Stepan     Chemical Co.     Thermophoam BWD  a trademarked alpha olefin sulfonate sold by Farbest Co.     Bioterge AS40  a trademarked alpha olefin sulfonate sold by Stepan     Chemical Co.     Suntech IV  a trademarked sulfonate sold by Sun Oil Co.

To determine a lower limit on the nitrogen flow rate, it was felt that aminimum increase in pressure drop over the cell to assure effectiveoperation would be about ten times the pressure drop with injection ofsteam only. Hence, the lower limit of nitrogen flow is the flow ratethat would cause the minimum desired 100 psig pressure drop across thecell. The results of Table I were linearly interpolated to obtain thenitrogen flow rate that would yield a 100 psig pressure drop with a 6%(corresponding to about a 1% in situ concentration) injection of foamingagent. It should be noted that these are only rough estimates and thatthe behavior of these foaming agents is not entirely linear.

                  TABLE II    ______________________________________                    Lower Limit N.sub.2 Flow Rate    Example           Foaming Agent  ml/min.   MSCF/bbl Steam    ______________________________________     2     Agent 2        0         0     3     Agent 3        0         0     4     Agent 4        3.0       0.18     7     Agent 7        23.2      1.38     8     Stepanflo 30   40.0      2.38     9     Stepanflo 1390 6.1       0.36    10     Thermophoam BWD                          20.3      1.21    11     Bioterge AS-40 6.3       0.37    12     Suntech IV     5.8       0.35    ______________________________________

EXAMPLES 13-14

Our research has linked the ability of a foaming agent to foam in theopen space of a cylinder at the elevated temperatures and pressures ofsteam floods with the ability of a foaming agent when co-injected withsteam and nitrogen to produce an increase in pressure drop across asandpack. This increase in pressure drop is indicative of the foamingagent's ability to retard the flow of steam through a hydrocarbonreservoir.

The Agent 1 carboxylate was compared to Agent 3, one of the best of theether sulfonates. To test the ability to generate a foam at steamflooding temperatures and pressures, 6% aqueous solutions of the foamingagents were added to an empty cylinder and foamed with nitrogen. As canbe seen from the results of Table III, the carboxylate Agent 1 achievedsimilar foam results to the ether sulfonate Agent 3.

                  TABLE III    ______________________________________               Foam Formation Rate (in/min) at    Ex.  Foaming Agent                     250° F., 200 psig                                   350° F., 400 psig    ______________________________________    13   Agent 1     13.46         2.48    14   Agent 3     9.6           2.99    ______________________________________

EXAMPLES 15-22

Further experiments were conducted with the foam testing apparatus totransform the pressure drop figures into more readily identifiablenumbers of percent oil recovery. The procedure of Examples 1-12 wasfollowed and the foam mixture was injected with 6% (corresponding toabout a 1% in situ concentration) foaming agent and 16.8 ml/min ofnitrogen. The three agents tested in Examples 20-22 offered commandingoil recovery efficiency advantages over the other foaming agents of theprior art. As the carboxylate Agent 1 of the present invention performedalmost as well as the ether sulfonate Agents 2, 3 and 4 in the pressuredrop tests, the carboxylate Agent 1 would be expected to recover muchmore oil than the other foaming agents of the prior art.

                  TABLE IV    ______________________________________    Example           Foaming Agent  Δ P (psi)                                    % Oil Recovery    ______________________________________    15     Thermophoam BWD                          69        28.3    16     Siponate 301-10                          32        31.0    17     Stepanflo 20   19        40.2    18     Igepal CA 720  11        4.1    19     COR-180        12        24.3    20     Agent 4        280       83.7    21     Agent 3        360       76.3    22     Agent 2        335       56.7    ______________________________________     Siponate 30110  a trademarked alpha olefin sulfonate sold by Alcolac Co.     Stepanflo 20  a trademarked alpha olefin sulfonate sold by Stepan Chemica     Co.     Igepal CA 720  a trademarked alkyl phenoxy polyoxyethylene ethanol sold b     GAF Corp.     COR180  trademarked oxyethylene sulfates sold by Chemical Oil Recovery Co

For comparison purposes, Table V has been compiled to present thefoaming agent concentration and nitrogen amounts used in recent fieldtests of foaming agents.

                  TABLE V    ______________________________________    Foaming                 bbl Agent  MSCF N.sub.2    Agent     Field         bbl Steam  bbl Steam    ______________________________________    Suntech IV              Kern River    0.714%     0.078    COR-180   Witmer B2-3   0.104%     0    Thermophoam              San Ardo      0.090%     0.06    BWD    Thermophoam              Midway-Sunset 0.060%     0.014    BWD    Stepanflo 30              Kern-River Mecca                            0.500%     0.0207    ______________________________________

It is apparent that these field tests were conducted with extemely lowconcentrations of carboxylate foaming agent and relatively smallquantities of injected nitrogen per barrel of steam. Although it isprobable that larger quantities of foaming agent and nitrogen could havebeen more effective, the economics of field tests, even on a smallscale, require the use of the smallest quantities practicable. Theeconomics become even more critical for large, field-wide applications.

It should be remembered that the carboxylate foaming agents of thepresent invention and Agents 2-7 performed substantially better than theagents of the prior art at higher concentrations in laboratory tests.Carboxylate foaming agents would probably be employed at concentrationssimilar to those of Table V in field tests.

Many other variations and modifications may be made in the conceptsdescribed above by those skilled in the art without departing from theconcepts of the present invention. Accordingly, it should be clearlyunderstood that the concepts disclosed in the description areillustrative only and are not intended as limitations on the scope ofthe invention.

What is claimed is:
 1. A process for recovering hydrocarbons from anunderground hydrocarbon formation penetrated by at least one injectionwell and at least one production well, which comprises:injecting steaminto an injection well; injecting into the injection well a mixture ofsteam, about 0.01 to about 5 thousand standard cubic feet of anon-condensable gas per barrel of steam in the injected mixture andabout 0.01% to about 5% by weight of a foaming agent based upon theweight of the steam in the injected mixture, said foaming agentrepresented by the formula,

    RO(R'O).sub.n R"CO.sub.2.sup.- M.sup.+,

where R is an alkyl radical, branched or linear, having from about 8 toabout 24 carbon atoms in the alkyl chain, R' is ethylene, propylene or amixture of ethylene and propylene, n has an average value of about 3 toabout 11, R" is methylene or ethylene, and M⁺ is an alkali metal orammonium ion; injecting steam into said injection well; and recoveringhydrocarbons and other fluids from a production well.
 2. The process ofclaim 1 for recovering hydrocarbons, wherein said mixture is injectedinto a steam override zone.
 3. The process of claim 1 for recoveringhydrocarbons, wherein R is an alkyl radical having about 11 to about 15carbon atoms, R' is ethylene, n has an average value of about 7, R" ismethylene and M⁺ is sodium.
 4. The process of claim 1 for recoveringhydrocarbons, wherein the concentration of said foaming agent in steamis increased as the steam injection rate is increased.
 5. The process ofclaim 1 for recovering hydrocarbons, wherein the non-condensable gas isselected from the group consisting of nitrogen, carbon dioxide, air,methane, ethane and flue gas.
 6. The process of claim 1 for recoveringhydrocarbons, wherein said mixture is injected into an injection wellnear the beginning of steam injection.
 7. The process of claim 1 forrecovering hydrocarbons, wherein said mixture is injected into aninjection well immediately prior to steam breakthrough at a productionwell.
 8. The process of claim 1 for recovering hydrocarbons, whereinsaid mixture is injected into an injection well after steam breakthroughat a production well.
 9. The process of claim 1 for recoveringhydrocarbons, wherein the non-condensable gas is injected at a rate ofabout 0.01 to about 1.5 thousand standard cubic feet per barrel of steamin the injected mixture.
 10. A process for recovering hydrocarbons froman underground hydrocarbon formation penetrated by at least oneinjection well and at least one production well, whichcomprises:injecting into an injection well a mixture of steam, about0.01 to about 5 thousand standard cubic feet of a non-condensable gasper barrel of steam in the injected mixture and about 0.01% to about 5%by weight of a foaming agent based upon the weight of the steam in theinjected mixture, said foaming agent represented by the formula,

    RO(R'O).sub.n R"CO.sub.2.sup.- M.sup.+,

where R is an alkyl radical, branched or linear, having from about 8 toabout 24 carbon atoms in the alkyl chain, R' is ethylene, propylene or amixture of ethylene and propylene, n has an average value of about 3 toabout 11, R" is methylene or ethylene, and M⁺ is an alkali metal orammonium ion; injecting steam into said injection well; and recoveringhydrocarbons and other fluids from a production well.
 11. A process forrecovering hydrocarbons from an underground hydrocarbon formationpenetrated by at least one injection well and at least one productionwell, which comprises:injecting steam into an injection well; injectinginto said injection well a mixture of steam, about 0.01 to about 1.5thousand standard cubic feet of nitrogen per barrel of steam in theinjected mixture and about 0.02% to about 1.5% by weight of a foamingagent based upon the weight of the steam in the injected mixture, saidfoaming agent represented by the formula

    CH.sub.3 (CH.sub.2).sub.10-14 O(CH.sub.2 CH.sub.2 O).sub.7 --CH.sub.2 --CO.sub.2 Na;

injecting steam into said injection well; and recovering hydrocarbonsand other fluids from a production well.